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TAG Oil Reports FY2018 Results

Vancouver, B.C. – June 29, 2018 – TAG Oil Ltd. (TSX: TAO and OTCQX: TAOIF) is pleased to report the annual and fourth quarter results for the fiscal year ending March 31, 2018. Most notably, the Company was successful in increasing itsrevenue to $23.7 millionalong with a 23% increase in operating netbacks to $30.66 per boe for FY2018.

Toby Pierce, TAG Oil’s CEO, commented “During fiscal 2018 we focused on our waterflood program, exploration drilling and ensuring we maintained our production assets. Despite an average Brent Oil price of $57.52 over the year, we still achieved operating cash flow of $8.7 million. In fiscal 2019, given the continued strength in Brent Oil pricing, our main focus will be on low-risk production growth, our waterflood program and adding to our exploration portfolio in New Zealand and Australia. I believe that we are in a better position to grow again after managing our way through this prolonged period of low oil prices and significant commitments. I am looking forward to FY2019, which I anticipate will be significantly better in terms of Brent Oil pricing, production and growth than the previous two fiscal years.”


  • At March 31, 2018, the Company had $1.8 million (March 31, 2017: $21.6 million) in cash and cash equivalents and $3.4 million (March 31, 2017: $25.9 million) in working capital and no debt.
  • Total gross proven plus probable reserves as at March 31, 2018 reflecting the Company’s 100% interest in PMP 38156 (Cheal), 70% interest in PMP 60291 (Cheal East) and 100% interest in PMP 53803 (Sidewinder), are estimated at 4.079 MMboe (94% oil) compared with 4.143 MMboe (92% oil) at March 31, 2017. The approximate 1.5% reserves reduction is due to:
    • An annual reserves revision of 287,000 boe (accounting for an approximate 7% increase in reserves).
    • Production of the 351,000 boe that the Company produced over FY2018 (accounting for an approximate 8% decrease in reserves).
  • Average net daily production decreased by 7% to 1,120 boe/d compared with 1,200 boe/d in FY2017.
  • Revenue increased by 1% to $23.7 million compared with $23.3 million in FY2017.
  • Operating netback increased by 23% for FY2018 to $30.66 per boe compared with $24.88 per boe for FY2017.
  • The Company relinquished the following permits:
    • 50% interest in the 1,102 acre onshore PEP 54879 (Cheal South) in August 2017.
    • 100% interest in the 22,054 acre onshore PEP 57063 (Wai-iti) in April 2017.
    • 100% interest in the 2,915 acre onshore PEP 55769 (Sidewinder East) in February 2018.
  • Capital expenditures totalled $24.2 million compared to $15.6 million for FY2017. The majority of the expenditure related to the following:
    • Taranaki development drilling and waterflood, workovers and facility improvements ($9.0 million).
    • Taranaki exploration drilling and other exploration activities ($11.7 million).
    • Australian PL17 seismic acquisition ($3.4 million).
    • Other Assets ($0.1 million).


  • Average net daily production increased by 7% for the quarter ended March 31, 2018, to 1,117 boe/d (75% oil) from 1,043 boe/d (79% oil) for the quarter ended December 31, 2017.
  • Operating netbacks decreased by 39% for the quarter ended March 31, 2018, to $26.42 per boe compared with $43.21 per boe for the quarter ended December 31, 2017.
  • Capital expenditures totaled $6.3 million for the quarter ended March 31, 2018, compared to $1.3 million for the quarter ended December 31, 2017.


TAG Oil’s capital budget for FY2019 is $12.4 million, which will be predominately funded by forecasted cash flow and working capital on hand. This includes $9.7 million of discretionary expenditures that are contingent mainly on sustained production and oil prices.

As TAG Oil continues the next phase of its reserve and production growth, the FY2019 capital budget focuses on low-expenditure, in-field production optimization opportunities and other necessary activities that are core to its business.These opportunities have been identified through an extensive ongoing geological and engineering review of the Company’s development and exploration acreage, and namely include the following:

  • Supplejack-1 commercialization at PEP 57065 (Sidewinder North);
  • Cheal-A11 and B5 perforations and rod pump installations, Cheal-A7 conversion and Cheal-B10 perforations;
  • Cheal-E4 injection conversion and Cheal-E2 recompletion at PMP 60291 (Cheal East);
  • Continued optimization of Cheal A site and Cheal E site waterflood programs;
  • Sidewinder-3 and 4 oil leg perforations, Sidewinder-5 and 6 permanent tie-ins;
  • Field development plan advancement for PEP 51153 (Puka);
  • Interpretation of the recently acquired Waitoriki 2D seismic data;
  • Continued appraisal of the Cardiff field; and
  • Meeting various permit obligations, including the acquisition and reprocessing of seismic data on PEP 57065 (Sidewinder North), which will allow TAG Oil to properly select potential exploration drilling opportunities.

TAG Oil is estimating that FY2019 revenue from operations will be $32.7 million, with production averaging approximately 1,300 boe/d (75% oil). TAG Oil expects to exit FY2019 with production of approximately 1,700 boe/d. This guidance is based on TAG Oil’s optimization of in-field opportunities and existing production, and assumes a Brent oil price for the year of US$65 per bbl. A sustained increase in oil prices would have a positive impact on this guidance. Should oil prices fall significantly below US$65 per bbl for any length of time, TAG Oil may reduce its capital program and/or activities to protect its balance sheet.

About TAG Oil Ltd.

TAG Oil ( is an international oil and gas explorer with established high netback production, development and exploration assets, including production infrastructure in New Zealand and Australia. TAG Oil is poised for significant reserve and production growth with several oil and gas fields under development and high-impact exploration in proven oil and gas fairways. TAG Oil currently has 85,282,252 shares outstanding.

For further information:

Chris Beltgens, Vice President, Corporate Development
Phone: 1-604-682-6496
Email: [email protected]

Cautionary Note Regarding Forward-Looking Statements and Disclaimer

Statements contained in this release that are not historical facts are forward-looking statements that involve various risks and uncertainty affecting the business ofTAG Oil. Such statements can generally, but not always, be identified by words such as “expects”, “plans”, “anticipates”, “intends”, “estimates”, “forecasts”, “schedules”, “prepares”, “potential” and similar expressions, or that events or conditions “will”, “would”, “may”, “could” or “should” occur. All estimates and statements that describe the Company’s plans relating to oil and natural gas production estimates and targets; statements regarding boe/d production capabilities; anticipated revenue from oil and gas  fields; capital expenditure programs and estimates; plans to drill additional wells; resource potential of unconventional plays; plans to grow baseline reserves, production, and cash flow in Taranaki; and other statements set out herein pertaining to operations are forward-looking statements under applicable securities laws and necessarily involve risks and uncertainties. Actual results may vary materially from the information provided in this release, and there is no representation by TAG Oilthat the actual results realized in the future will be the same in whole or in part as those presented herein.  

Other factors that could cause actual results to differ from those contained in the forward-looking statements are also set forth in filings that TAG Oiland its independent evaluator have made, including TAG Oil’s most recently filed reports in Canada under National Instrument 51-101, which can be found under TAG Oil’s SEDAR profile at TAG Oilundertakes no obligation, except as otherwise required by law, to update these forward-looking statements in the event that management’s beliefs, estimates or opinions, or other factors change.

Disclosure provided herein in respect of boe (barrels of oil equivalent) may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf:1bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on analysis of drilling, geological, geophysical and engineering data, the use of established technology, and specified economic conditions, which are generally accepted as being reasonable, and shall be disclosed.

Reserves are classified according to the degree of certainty associated with the estimates. Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.

The qualitative certainty levels referred to in the definitions above are applicable to “individual reserves entities”, which refers to the lowest level at which reserves calculations are performed, and to “reported reserves”, which refers to the highest level sum of individual entity estimates for which reserves estimates are presented. Reported reserves should target the following levels of certainty under a specific set of economic conditions:

  • at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves;
  • at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves; and
  • at least a 10 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable plus possible reserves.

The reserve estimates contained herein were prepared by ERC Equipoise Ltd., a qualified reserves evaluator in accordance with National Instrument 51-101 and the Canadian Oil and Gas Evaluation Handbook, with an effective date of March 31, 2018. They are estimates only and there is no guarantee that the estimated reserves or resources will be recovered. The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.

The Company uses the term“operating netback” for measurement within this release that does not have a standardized meaning prescribed by generally accepted accounting principles (“GAAP”), including International Financial Reporting Standards (“IFRS”), and this measurement may differ from other companies and accordingly may not be comparable to measures used by other companies. The term “operating netback” is not a recognized measure under the applicable IFRS. Management of the Company believes that this term is useful to provide shareholders and potential investors with additional information, in addition to profit and loss and cash flow from operating activities as defined by IFRS, for evaluating the Company’s operating performance and leverage. References to “operating netback” denotes oil and gas revenue, less royalty expenses, operating expenses and transportation and marketing expenses.